oil and gas supply module - u.s. energy information administration

Oil and Gas Supply Module

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111U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2012


The NEMS Oil and Gas Supply Module (OGSM) constitutes a comprehensive framework with which to analyze crude oil and natural gas exploration and development on a regional basis (Figure 8). The OGSM is organized into 4 submodules: Onshore Lower 48 Oil and Gas Supply Submodule, Offshore Oil and Gas Supply Submodule, Oil Shale Supply Submodule[1], and Alaska Oil and Gas Supply Submodule. A detailed description of the OGSM is provided in the EIA publication, Model Documentation Report: The Oil and Gas Supply Module (OGSM), DOE/EIA-M063(2011), (Washington, DC, 2011). The OGSM provides crude oil and natural gas short-term supply parameters to both the Natural Gas Transmission and Distribution Module and the Petroleum Market Module. The OGSM simulates the activity of numerous firms that produce oil and natural gas from domestic fields throughout the United States.

Figure 8. Oil and Gas Supply Model regions

Source: U.S. Energy Information Administration, Office of Energy Analysis.

Rocky Mountain - 5

Rocky Mountains

West Coast

Midcontinent Northeast

Gulf Coast Southwest

Atlantic

Shallow Gulf of Mexico

Deep Gulf of Mexico

U.S. Energy Information Administration | Assumptions to the Annual Energy Outlook 2012112


OGSM encompasses domestic crude oil and natural gas supply by several recovery techniques and sources. Crude oil recovery includes improved oil recovery processes such as water flooding, infill drilling, and horizontal continuity, as well as enhanced oil recovery processes such as CO2 flooding, steam flooding, and polymer flooding. Recovery from highly fractured, continuous zones (e.g. Austin chalk and Bakken shale formations) is also included. Natural gas supply includes resources from low- permeability tight sand formations, shale formations, coalbed methane, and other sources.

Key assumptionsDomestic oil and natural gas technically recoverable resourcesDomestic oil and natural gas technically recoverable resources [2] consist of proved reserves [3] and unproved resources [4]. OGSM resource assumptions are based on estimates of technically recoverable resources from the United States Geological Survey (USGS) and the Bureau of Ocean Energy Management (BOEM) of the Department of the Interior [5]. Supplemental adjustments to the USGS continuous crude oil and natural gas resources are made to incorporate the latest available production data and to add some frontier plays that are not quantitatively assessed by the USGS. While undiscovered resources for Alaska are based on USGS estimates, estimates of recoverable resources are obtained on a field-by-field basis from a variety of sources including trade press. Published estimates in Tables 9.1 and 9.2 reflect the removal of intervening reserve additions between the date of the latest available assessment and January 1, 2010.

Table 9.1. Technically recoverable U.S. crude oil resources as of January 1, 2010billion barrels

Proved Reserves Unproved ResourcesTotal Technically

Recoverable Resources

Lower 48 Onshore 14.2 112.6 126.7 Northeast 0.2 4.4 4.6 Gulf Coast 1.5 21.4 22.8 Midcontinent 1.3 12.7 14.0 Southwest 5.3 27.6 32.9 Rocky Mountain 3.2 23.0 26.2 West Coast 2.7 23.5 26.2

Lower 48 Offshore 4.6 50.3 54.8 Gulf (currently available) 4.1 38.7 42.7 Eastern/Central Gulf (unavailable until 2022) 0.0 3.7 3.7 Pacific 0.5 6.6 7.1 Atlantic 0.0 1.4 1.4Alaska (Onshore and Offshore) 3.6 35.0 38.6

Total U.S. 22.3 197.9 220.2Note: Crude oil resources include lease condensates but do not include natural gas plant liquids or kerogen (oil shale). Resources in areas where drilling is officially prohibited are not included in this table. The estimate of 7.3 billion barrels of crude oil resources in the Northern Atlantic, Northern and Central Pacific, and within a 50-mile buffer off the Mid and Southern Atlantic OCS is also excluded from the technically recoverable volumes because leasing is not expected in these areas by 2035.Source: Onshore, State Offshore, and Alaska - U.S. Geological Survey (USGS); Federal (Outer Continental Shelf) Offshore - Bureau of Ocean Energy Management (formerly the Minerals Management Service); Proved Reserves - U.S. Energy Information Administration. Table values reflect removal of intervening reserve additions between the date of the latest available assessment and January 1, 2010.

Lower 48 onshoreThe Onshore Lower 48 Oil and Gas Supply Submodule (OLOGSS) is a play-level model used to analyze crude oil and natural gas supply from onshore lower 48 sources. The methodology includes a comprehensive assessment method for determining the relative economics of various prospects based on financial considerations, the nature of the resource, and the available technologies. The play-level unproved technically recoverable resource assumptions for tight oil, shale gas, tight gas, and coalbed methane are shown in Tables 9.3-9.6. The general methodology relies on a detailed economic analysis of potential projects in known fields, enhanced oil recovery projects, and undiscovered resources. The projects which are economically viable are developed subject to the availability of resource development constraints which simulate the existing and expected infrastructure of the oil and gas industries. For crude oil projects, advanced secondary or improved oil recovery techniques (e.g. infill drilling and horizontal continuity) and enhanced oil recovery (e.g. CO2 flooding, steam flooding, and polymer flooding) processes are explicitly represented. For natural gas projects, the OLOGSS represents supply from shale formations, tight sands formations, coalbed methane, and other sources.



Table 9.2. Technically recoverable U.S. natural gas resources as of January 1, 2010trillion cubic feet

Proved Reserves

Unproved Resources

Total Technically Recoverable

Resources

Lower 48 Onshore Non Associated Natural Gas 230.0 1250.2 1480.3 Tight Gas 87.9 422.7 510.7 Northeast 5.2 51.8 57.0 Gulf Coast 24.3 96.8 121.1 Midcontinent 7.4 22.1 29.5 Southwest 3.4 24.5 27.9 Rocky Mountain 47.6 222.0 267.6 West Coast 0.0 7.5 7.5 Shale Gas 60.6 481.8 542.3 Northeast 7.1 216.5 223.6 Gulf Coast 10.9 129.7 140.6 Midcontinent 15.4 39.8 55.2 Southwest 26.5 46.1 72.6 Rocky Mountain 0.7 37.4 38.1 West Coast 0.0 12.2 12.2 Coalbed Methane 18.6 122.2 140.8 Northeast 2.5 4.1 6.5 Gulf Coast 1.3 2.2 3.5 Midcontinent 0.7 38.3 38.9 Southwest 0.5 5.8 6.2 Rocky Mountain 13.6 61.6 75.2 West Coast 0.0 10.3 10.3 Other 63.0 223.5 286.5 Northeast 7.0 29.2 36.2 Gulf Coast 10.9 101.2 112.0 Midcontinent 20.3 26.5 46.8 Southwest 16.9 18.6 35.5 Rocky Mountain 7.3 35.0 42.3 West Coast 0.6 13.1 13.7Lower 48 Onshore Associated-Dissolved Gas 18.4 146.2 164.6 Northeast 0.4 0.6 0.9 Gulf Coast 1.7 23.9 25.6 Midcontinent 1.7 12.3 14.0 Southwest 8.3 40.4 48.7 Rocky Mountain 4.1 45.9 50.0 West Coast 2.1 23.2 25.3Lower 48 Offshore 15.0 262.6 277.6 Gulf (currently available) 14.2 218.4 232.5 Eastern/Central Gulf (unavailable until 2022) 0.0 21.5 21.5 Pacific 0.8 10.4 11.2 Atlantic 0.0 12.4 12.4Alaska (Onshore and Offshore) 9.1 271.7 280.8Total U.S. 272.5 1930.7 2203.3Note: Resources in other areas where drilling is officially prohibited are not included. The estimate of 32.9 trillion cubic feet of natural gas resources in the Northern Atlantic, Northern and Central Pacific, and within a 50-mile buffer off the Mid and Southern Atlantic OCS is also excluded from the technically recoverable volumes because leasing is not expected in these areas by 2035. Source: Onshore, State Offshore, and Alaska - U.S. Geological Survey (USGS) with adjustments to tight gas, shale gas, and coalbed methane resources; Federal (Outer Continental Shelf) Offshore - Bureau of Ocean Energy Management (formerly the Minerals Management Service); Proved Reserves - U.S. Energy Information Administration. Table values reflect removal of intervening reserve additions between the date of the latest available assessment and January 1, 2010.



The OLOGSS evaluates the economics of future crude oil and natural gas exploration and development from the perspective of an operator making an investment decision. An important aspect of the economic calculation concerns the tax treatment. Tax provisions vary with the type of producer (major, large independent, or small independent). For AEO2012, the economics of potential projects reflect the tax treatment provided by current laws for large independent producers. Relevant tax provisions are assumed unchanged over the life of the investment. Costs are assumed constant over the investment life but vary across region, fuel, and process type. Operating losses incurred in the initial investment period are carried forward and used against revenues generated by the project in later years.

Table 9.3. U.S. unproved technically recoverable tight oil resources by play - AEO2012

Region Basin PlayArea (mi2)

Average Well Spacing

(wells/mi2)% of Area Untested

% of Area with Potential

Average EUR (mmb/well)

TRR (mmb)

2 West Gulf Austin Chalk 16,078 3 72% 61% 0.13 2,6882 West Gulf Eagle Ford Shale 3,200 5 100% 54% 0.28 2,4613 Anadarko Woodford Shale 3,120 6 100% 88% 0.02 3934 Permian Avalon/Bone Springs Shale 1,313 4 100% 78% 0.39 1,5934 Permian Spraberry 1,085 6 99% 72% 0.11 5105 Rocky Mountain Basins Niobrara 20,385 8 97% 80% 0.05 6,5005 Williston Bakken Shale 6,522 2 77% 97% 0.55 5,3726 San Joaquin/Los Angeles Monterey/Santos Shale 2,520 12 98% 93% 0.50 13,709Total 33,226Source: U.S. Energy Information Administration, Office of Energy Analysis.

Table 9.4. U.S. unproved technically recoverable shale gas resources by play - AEO2012





Average EUR (bcf/well)

TRR (bcf)

1 Appalachian Devonian Big Sandy 10,669 6 82% 20% 0.57 6,0201 Appalachian Devonian Greater Sitstone Area 22,914 6 95% 20% 0.33 8,6451 Appalachian Devonian Low Thermal Maturity 45,844 6 99% 10% 0.50 13,5921 Appalachian Marcellus - KY Western 207 5 100% 7% 0.13 111 Appalachian Marcellus - MD Foldbelt 435 4 100% 5% 0.21 181 Appalachian Marcellus - MD Interior 763 4 100% 37% 0.52 6301 Appalachian Marcellus - NY Interior 10,381 4 100% 37% 2.43 40,1231 Appalachian Marcellus - NY Western 7,985 5 100% 7% 0.13 4251 Appalachian Marcellus - OH Interior 361 4 99% 37% 0.52 2961 Appalachian Marcellus - OH Western 13,515 5 100% 7% 0.13 7201 Appalachian Marcellus - PA Foldbelt 7,951 4 100% 5% 0.21 3231 Appalachian Marcellus - PA Interior 23,346 4 98% 37% 2.43 88,1801 Appalachian Marcellus - PA Western 6,582 5 100% 7% 0.13 3511 Appalachian Marcellus - TN Foldbelt 353 4 100% 5% 0.21 141 Appalachian Marcellus - VA Foldbelt 7,492 4 100% 5% 0.21 3041 Appalachian Marcellus - VA Interior 321 4 100% 37% 0.52 2651 Appalachian Marcellus - VA Western 653 5 100% 7% 0.13 351 Appalachian Marcellus - WV Foldbelt 2,833 4 100% 5% 0.21 1151 Appalachian Marcellus - WV Interior 9,989 4 99% 37% 0.52 8,1861 Appalachian Marcellus - WV Western 10,901 5 98% 7% 0.13 5711 Appalachian Northwestern Ohio 6,000 4 100% 50% 0.22 2,6431 Appalachian Utica 16,590 4 100% 21% 1.13 15,7121 Illinois New Albany 1,600 8 99% 50% 1.72 10,9041 Michigan Antrim 12,000 8 91% 60% 0.35 18,4112 Black Warrior Floyd-Neal/Conasauga 2,429 2 100% 65% 1.52 4,8052 TX-LA-MS Salt Haynesville - LA 3,730 8 96% 49% 3.28 46,1022 TX-LA-MS Salt Haynesville - TX 5,590 8 99% 24% 1.87 19,7582 West Gulf Coast Eagle Ford - Dry 2,200 6 99% 43% 1.78 10,0442 West Gulf Coast Eagle Ford - Wet 5,400 6 99% 49% 2.57 40,1752 West Gulf Coast Pearsall 1,420 6 100% 85% 1.22 8,817



Table 9.4. U.S. unproved technically recoverable shale gas resources by play - AEO2012 (cont.)






TRR (bcf)

3 Anadarko Woodford 3,350 4 99% 29% 2.89 10,9813 Arkoma Caney 2,890 4 100% 29% 0.34 1,1353 Arkoma Chattanooga 696 8 100% 29% 0.99 1,6173 Arkoma Fayetteville - Central 3,451 8 88% 22% 1.71 9,0703 Arkoma Fayetteville - West 2,402 8 100% 25% 0.86 4,1703 Arkoma Woodford - Western Arkoma 3,000 8 98% 23% 1.97 10,6783 Southwestern OK Woodford 1,200 4 99% 20% 2.31 2,1894 Fort Worth Barnett 6,458 8 71% 30% 1.69 18,6514 Permian Barnett-Woodford 2,691 4 99% 95% 2.70 27,4705 Greater Green River Hilliard-Baxter-Mancos 17,911 8 100% 25% 0.37 13,2855 San Juan Lewis 1,557 3 100% 95% 2.20 9,7605 Uinta Mancos 3,880 8 99% 40% 0.88 10,8735 Williston Gammon 4,207 2 100% 91% 0.46 3,4916 Columbia Basin-Centered 6,387 8 100% 17% 1.40 12,220Total 481,783Source: U.S. Energy Information Administration, Office of Energy Analysis.

Table 9.5. U.S. unproved technically recoverable tight gas resources by play - AEO2012






TRR (bcf)

1 Appalachian Berea Sandstone 51,863 8 86% 18% 0.18 11,4011 Appalachian Clinton/Medina High 14,773 8 81% 28% 0.25 6,7861 Appalachian Clinton/Medina Moderate/Low 27,281 15 86% 59% 0.08 16,1361 Appalachian Tuscarora Sandstone 42,495 8 100% 1% 0.69 1,4851 Appalachian Upper Devonian High 12,775 10 58% 67% 0.21 10,4931 Appalachian Upper Devonian Moderate/Low 29,808 10 82% 37% 0.06 5,4922 East Texas Cotton Valley/Bossier 14,794 12 96% 29% 1.39 69,7202 Texas-Gulf Olmos 8,233 4 97% 56% 0.44 7,8092 Texas-Gulf Vicksburg 3,667 8 93% 11% 2.36 6,9292 Texas-Gulf Wilcox/Lobo 2,982 8 79% 41% 1.60 12,3733 Anadarko Cherokee/Redfork 1,978 4 58% 30% 0.90 1,2203 Anadarko Cleveland 2,562 4 88% 45% 0.91 3,7243 Anadarko Granite Wash/Atoka 7,790 4 98% 28% 1.72 14,8213 Arkoma Arkoma Basin 1,000 8 69% 32% 1.30 2,3154 Permian Abo 1,578 8 91% 99% 1.00 11,3864 Permian Canyon 6,602 8 91% 85% 0.22 13,1055 Denver Denver/Jules 4,500 16 88% 86% 0.24 13,2125 Greater Green River Deep Mesaverde 16,416 4 100% 11% 0.41 2,9395 Greater Green River Fort Union/Fox Hills 3,858 8 100% 5% 0.70 1,0595 Greater Green River Frontier (Deep) 15,619 4 100% 7% 2.58 10,8015 Greater Green River Frontier (Moxa Arch) 2,334 8 89% 16% 1.20 3,0765 Greater Green River Lance 5,500 8 100% 9% 6.60 24,9515 Greater Green River Lewis 5,172 8 99% 37% 1.32 19,8135 Greater Green River Shallow Mesaverde (1) 5,239 4 95% 50% 1.25 12,4575 Greater Green River Shallow Mesaverde (2) 6,814 8 100% 49% 0.67 17,8745 Piceance Iles/Mesaverde 1,172 8 99% 94% 0.73 6,3795 Piceance North Basin Williams Fork/Mesaverde 908 8 100% 90% 0.65 4,2785 Piceance South Basin Williams Fork/Mesaverde 908 32 99% 84% 0.65 15,6485 San Juan Central Basin/Dakota 3,918 8 88% 99% 0.98 26,6635 San Juan Central Basin/Mesaverde 3,689 8 83% 47% 0.82 9,4835 San Juan Picture Cliffs 6,558 4 63% 1% 0.48 36



Table 9.5. U.S. unproved technically recoverable tight gas resources by play - AEO2012 (cont.)






TRR (bcf)

5 Uinta Basin Flank Mesaverde 1,708 8 100% 43% 0.99 5,7675 Uinta Deep Synclinal Mesaverde 2,893 8 100% 14% 0.99 3,2925 Uinta Tertiary East 1,600 16 96% 33% 0.58 4,6905 Uinta Tertiary West 1,603 8 100% 21% 4.06 10,9145 Williston High Potential 2,000 4 77% 89% 0.61 3,3435 Williston Low Potential 3,000 4 99% 75% 0.21 1,8865 Williston Moderate Potential 2,000 4 98% 79% 0.33 2,0715 Wind River Fort Union/Lance Deep 2,500 4 100% 80% 0.54 4,2615 Wind River Fort Union/Lance Shallow 1,500 8 100% 95% 1.17 13,1975 Wind River Mesaverde/Frontier Deep 250 4 98% 45% 1.99 8765 Wind River Mesaverde/Frontier Shallow 250 4 91% 92% 1.25 1,0376 Columbia Basin-Centered 1,500 8 100% 50% 1.26 7,521Total 422,719Source: U.S. Energy Information Administration, Office of Energy Analysis.

Table 9.6. U.S. unproved technically recoverable coalbed methane resources by play - AEO2012






TRR (bcf)

1 Appalachian Central Basin 3,870 8 98% 34% 0.18 1,8351 Appalachian North Appalachian Basin - High 3,817 12 100% 9% 0.12 5361 Appalachian North Appalachian Basin - Mod/Low 8,906 12 100% 5% 0.08 4691 Illinois Central Basin 1,714 8 100% 75% 0.12 1,2242 Black Warrior Extention Area 700 8 100% 21% 0.08 942 Black Warrior Main Area 1,000 12 71% 97% 0.21 1,7062 Cahaba Cahaba Coal Field 387 8 93% 73% 0.18 3793 Midcontinent Arkoma 2,998 8 98% 93% 0.22 4,6923 Midcontinent Cherokee 3,550 8 100% 97% 0.06 1,7843 Midcontinent Forest City 36,917 8 100% 63% 0.17 31,7814 Raton Southern 2,028 8 100% 95% 0.37 5,7705 Greater Green River Deep 3,600 4 100% 45% 0.60 3,8795 Greater Green River Shallow 720 8 100% 90% 0.20 1,0535 Greater Green River Western Wyoming 15,097 2 100% 52% 0.46 7,1315 Piceance Deep 2,000 4 100% 77% 0.60 3,6775 Piceance Divide Creek 144 8 99% 95% 0.18 1945 Piceance Shallow 2,000 4 99% 94% 0.30 2,2305 Piceance White River Dome 216 8 99% 94% 0.41 6575 Powder River Big George/Lower Fort Union 2,880 16 100% 55% 0.26 6,5075 Powder River Wasatch 216 8 100% 95% 0.06 925 Powder River Wyodak/Upper Fort Union 6,600 20 99% 94% 0.14 16,7255 Raton Northern 470 8 100% 73% 0.35 9575 Raton Purgatoire River 360 8 97% 50% 0.31 4305 San Juan Fairway NM 670 4 84% 30% 1.14 7745 San Juan North Basin 2,060 4 84% 78% 0.28 1,5115 San Juan North Basin CO 1,980 4 86% 98% 1.51 10,1235 San Juan South Basin 1,190 4 94% 92% 0.20 8205 San Juan South Menefee NM 7,454 5 100% 5% 0.10 1775 Uinta Blackhaw 1,186 8 100% 97% 0.16 1,4235 Uinta Ferron 400 8 97% 59% 0.78 1,4095 Uinta Sego 534 4 100% 64% 0.31 4175 Wind River Mesaverde 3,018 2 100% 13% 1.73 1,3876 Western Washington Bellinham/Western Cascade/ 3,655 5 100% 60% 0.94 10,339Total 122,183Source: U.S. Energy Information Administration, Office of Energy Analysis.



TechnologyTechnology advances, including improved drilling and completion practices, as well as advanced production and processing operations, are explicitly modeled to determine the direct impacts on supply, reserves, and various economic parameters. The success of the technology program is measured by estimating the probability that the technology development program will be successfully completed. It reflects the pace at which technology performance improves and the probability that the technology project will meet the program goals. There are four possible curves which represent the adoption of the technology: convex, concave, sigmoid/logistic and linear. The convex curve corresponds to rapid initial market penetration followed by slow market penetration. The concave curve corresponds to slow initial market penetration followed by rapid market penetration. The sigmoid/logistic curve represents a slow initial adoption rate followed by rapid increase in adoption and then slow adoption again as the market becomes saturated. The linear curve represents a constant rate of market penetration, and may be used when no other predictions can be made.

The market penetration curve is a function of the relative economic attractiveness of the technology instead of being a time-dependent function. A technology will not be implemented unless the benefits through increased production or cost reductions are greater than the cost to apply the technology. As a result, the market penetration curve provides a limiting value on commercialization instead of a specific penetration path. In addition to the curve, the implementation probability captures the fact that not all technologies that have been proven in the lab are able to be successfully implemented in the field. The specific technology levers and assumptions are shown in Table 9.7.

Table 9.7. Onshore lower 48 technology assumptionsUltimateMarket

Penetration

MarketPenetration

Curve

Probability ofSuccessful

R&DProbability of

Implementation

DrillingSuccess

Rate

ExplorationSucess

RateInjection

Rate

EstimatedUltimateRecovery

Conventional OilInfill Drilling 0.59 linear 0.5 0.44 0.03 0.03 -- 0.01Horizonal Continuity 0.6 linear 0.51 0.44 0.03 0.03 0.25 0.023Horizontal Profile 0.6 concave 0.49 0.45 0.03 0.03 0.02 0.005CO2 Flooding 0.61 linear 0.51 0.43 0.03 0.03 0.38 0.042Steam Flooding 0.6 logistic 0.49 0.44 0.03 0.03 0.01 0.09Polymer Flooding 0.61 concave 0.5 0.44 0.03 0.03 0.123 0.06Profile Modification 0.59 concave 0.51 0.42 0.03 0.03 -- 0.06Undiscovered 0.6 concave 0.48 0.44 0.03 0.03 -- 0.08

Tight Oil 0.6 concave 0.48 0.44 0.03 0.03 -- 0.08Conventional Gas

Developing 0.61 linear 0.48 0.46 0.03 0.03 -- 0.04Undiscovered 0.61 linear 0.49 0.45 0.03 0.03 -- 0.07

Tight GasDeveloping 0.61 linear 0.48 0.46 0.03 0.03 -- 0.04Undiscovered 0.61 linear 0.49 0.45 0.03 0.03 -- 0.05

Shale GasDeveloping 0.61 linear 0.48 0.45 0.03 0.03 -- 0.08Undiscovered 0.61 linear 0.48 0.45 0.03 0.03 -- 0.7

Coalbed MethaneDeveloping 0.6 linear 0.5 0.44 0.03 0.03 -- 0.05Undiscovered 0.6 linear 0.49 0.43 0.03 0.03 -- 0.05




CO2 enhanced oil recoveryFor CO2 miscible flooding, the OLOGSS incorporates both industrial and natural sources of CO2. The industrial sources of CO2 are:• Hydrogen plants• Ammonia plants• Ethanol plants• Cement plants• Refineries (hydrogen)• Fossil fuel power plants• Natural gas processing• Coal/biomass to liquids (CBTL)Technology and market constraints prevent the total volumes of CO2 (Table 9.8) from becoming immediately available. The development of the CO2 market is divided into 2 periods: 1) development phase and 2) market acceptance phase. During the development phase, the required capture equipment is developed, pipelines and compressors are constructed, and no CO2 is available. During the market acceptance phase, the capture technology is being widely implemented and volumes of CO2 first become available. The number of years in each development period is shown in Table 9.9. CO2 is available from planned Carbon Sequestion and Storage (CCS) power plants funded by American Recovery and Reinvestment Act of 2009 (ARRA) starting in 2016.

Table 9.8. Maximum volume of CO2 availablebillion cubic feet

OGSM Region Natural Hydrogen Ammonia Ethanol CementRefineries

(hydrogen)Power Plants

Natural Gas Processing

East Coast 0 3 0 52 94 17 12980 23

Gulf Coast 292 0 78 0 86 114 3930 114

Midcontinent 16 0 0 175 48 1 752 0

Southwest 657 0 0 68 74 0 0 0

Rocky Mountains 80 0 3 23 35 62 2907 12

West Coast 0 0 0 4 48 93 1134 40

Northern Great Plains 0 0 0 9 3 16 60 6

Source: U.S. Energy Information Administration. Office of Energy Analysis.

Table 9.9. CO2 availability assumptions

Source TypeDevelopment Phase

(years)

Market Acceptance Phase

(years)Ultimate Market

Acceptance

Natural 1 10 100%

Hydrogen 4 10 100%

Ammonia 2 10 100%

Ethanol 4 10 100%

Cement 7 10 100%

Refineries (hydrogen) 4 10 100%

Power Plants 12 10 100%

Natural Gas Processing 2 10 100%

Source: U.S. Energy Information Administration. Office of Energy Analysis.



The cost of CO2 from natural sources is a function of the oil price. For industrial sources of CO2, the cost to the producer includes the cost to capture, compress to pipeline pressure, and transport to the project site via pipeline within the region (Table 9.10). Inter-regional transportation costs add $0.40 per Mcf for every region crossed.

Table 9.10. Industrial CO2 capture & transportation costs by region$/Mcf

OGSM Region Hydrogen Ammonia Ethanol CementRefineries

(hydrogen) Power PlantsNatural Gas

Processing CBTL

East Coast $2.44 $2.10 $2.23 $4.29 $2.44 $5.96 $1.92 $1.91

Gulf Coast $1.94 $2.10 $2.23 $4.29 $1.94 $5.96 $1.92 $1.91

Midcontinent $2.07 $2.10 $2.23 $4.29 $2.07 $5.96 $1.92 $1.91

Southwest $2.02 $2.10 $2.23 $4.29 $2.02 $5.96 $1.92 $1.91

Rocky Mountains $2.03 $2.10 $2.23 $4.29 $2.03 $5.96 $1.92 $1.91

West Coast $2.01 $2.10 $2.23 $4.29 $2.01 $5.96 $1.92 $1.91

Northern Great Plains $2.05 $2.10 $2.23 $4.29 $2.05 $5.96 $1.92 $1.91


Lower 48 offshoreMost of the Lower 48 offshore oil and gas production comes from the deepwater of the Gulf of Mexico (GOM). Production from currently producing fields and industry-announced discoveries largely determines the short-term oil and natural gas production projection. For currently producing fields, a 20-percent exponential decline is assumed for production except for natural gas production from fields in shallow water, which uses a 30-percent exponential decline. Fields that began production after 2008 are assumed to remain at their peak production level for 2 years before declining. The assumed field size and year of initial production of the major announced deepwater discoveries that were not brought into production by 2011 are shown in Table 9.11. A field that is announced as an oil field is assumed to be 100 percent oil and a field that is announced as a gas field is assumed to be 100 percent gas. If a field is expected to produce both oil and gas, 70 percent is assumed to be oil and 30 percent is assumed to be gas. Production is assumed to:• ramp up to a peak level in 2 to 4 years depending on the size of the field,• remain at the peak level until the ratio of cumulative production to initial resource reaches 20 percent for oil and 30 percent for

natural gas,• and then decline at an exponential rate of 20-30 percent.The discovery of new fields (based on BOEM’S field size distribution) is assumed to follow historical patterns. Production from these fields is assumed to follow the same profile as the announced discoveries (as described in the previous paragraph). Advances in technology for the various activities associated with crude oil and natural gas exploration, development, and production can have a profound impact on the costs associated with these activities. The specific technology levers and values for the offshore are presented in Table 9.12.Leasing is assumed to be available in 2018 in the Mid and South Atlantic, in 2023 in the South Pacific, and after 2035 in the North Atlantic, Florida straits, Pacific Northwest, and North and Central California.

Alaska crude oil productionProjected Alaska oil production includes both existing producing fields and undiscovered fields that are expected to exist, based upon the region’s geology. The existing fields category includes the expansion fields around the Prudhoe Bay and Alpine Fields for which companies have already announced development schedules. Projected North Slope oil production also includes the initiation of oil production in the Point Thomson Field in 2016. Alaska crude oil production from the undiscovered fields is determined by the estimates of available resources in undeveloped areas and the net present value of the cash flow calculated for these undiscovered fields based on the expected capital and operating costs, and on the projected prices. The discovery of new Alaskan oil fields is determined by the number of new wildcat exploration wells drilled each year and by the average wildcat success rate. The North Slope and South-Central wildcat well success rates are based on the success rates reported to the Alaska Oil and Gas Conservation Commission for the period of 1977 through 2008.



Table 9.11. Assumed size and initial production year of major announced deepwater discoveries Field/Project Name Block

Water Depth (feet)

Year of Discovery

Field Size Class

Field Size (MMBoe)

Start Year of Production

Pyrenees GB293 2100 2009 12 89 2012 Wide Berth GC490 3700 2009 12 89 2012 West Tonga GC726 4674 2007 12 89 2012 Bushwood GB463 2700 2009 13 182 2012 Mandy MC199 2478 2010 13 182 2012 Cascade WR206 8143 2002 14 372 2012 Chinook WR469 8831 2003 14 372 2012 Axe DC004 5831 2010 12 89 2013 Dalmatian DC048 5876 2008 12 89 2013 Big Foot WR029 5235 2005 12 89 2013 Knotty Head GC512 3557 2005 14 372 2013 Tubular Bells MC725 4334 2003 12 89 2014 Lucius KC875 7168 2009 13 182 2014 St. Malo WR678 7036 2003 14 372 2014 Jack WR759 6963 2004 14 372 2014 Samurai GC432 3400 2009 12 89 2015 Heidelberg GC859 5000 2009 13 182 2015 Kodiak MC771 4986 2008 13 182 2015 Pony GC468 3497 2006 14 372 2015 Freedom MC948 6095 2008 15 691 2015 Stones WR508 9556 2005 12 89 2016 Mission Deep GC955 7300 1999 13 182 2016 Vito MC984 4038 2009 13 182 2016 Tiber KC102 4132 2009 15 691 2016 Kaskida KC292 5860 2006 15 691 2016 Shenandoah WR052 5750 2009 13 182 2017 Julia WR627 7087 2007 12 89 2018 Buckskin KC872 6920 2009 13 182 2018

Hadrian South KC964 7586 2009 13 182 2019

Appomattox MC392 7217 2009 15 691 2019

Cardamom GB427 2720 2010 13 182 2020

Hadrian North KC919 7000 2010 14 372 2020Source: U.S. Energy Information Administration, Office of Energy Analysis.

New wildcat exploration drilling rates are determined differently for the North Slope and South-Central Alaska. North Slope wildcat well drilling rates were found to be reasonably well correlated with prevailing West Texas Intermediate crude oil prices. Consequently, an ordinary least squares statistical regression was employed to develop an equation that specifies North Slope wildcat exploration well drilling rates as a function of prevailing West Texas Intermediate crude oil prices. In contrast, South-Central wildcat well drilling rates were found to be uncorrelated to crude oil prices or any other criterion. However, South-Central wildcat well drilling rates on average equaled just over 3 wells per year during the 1977 through 2008 period, so 3 South-Central wildcat exploration wells are assumed to be drilled every year in the future.



Table 9.12. Offshore exploration and production technology levels

Technology LevelTotal Improvement

(percent) Number of Years

Exploration success rates 30 30

Delay to commence first exploration and between 15 30

Exploration & development drilling costs 30 30

Operating cost 30 30

Time to construct production facility 15 30

Production facility construction costs 30 30

Initial constant production rate 15 30

Decline rate 0 30


On the North Slope, the proportion of wildcat exploration wells drilled onshore relative to those drilled offshore is assumed to change over time. Initially, only a small proportion of all the North Slope wildcat exploration wells are drilled offshore. However, over time, the offshore proportion increases linearly, so that after 20 years, 50 percent of the North Slope wildcat wells are drilled onshore and 50 percent are drilled offshore. The 50/50 onshore/offshore wildcat well apportionment remains constant through the remainder of the forecast in recognition of the fact that offshore North Slope wells and fields are considerably more expensive to drill and develop, thereby providing an incentive to continue drilling onshore wildcat wells even though the expected onshore field size is considerably smaller than the oil fields expected to be discovered offshore.The size of the new oil fields discovered by wildcat exploration drilling is based on the expected field sizes of the undiscovered Alaska oil resource base, as determined by the U.S. Geological Survey for the onshore and State offshore regions of Alaska, and by the Bureau of Ocean Energy Management (BOEM) (formerly known as the U.S. Minerals Management Service) for the Federal offshore regions of Alaska. It is assumed that the largest undiscovered oil fields will be found and developed first and in preference to the small and midsize undiscovered fields. As the exploration and discovery process proceeds and as the largest oil fields are discovered and developed, the discovery and development process proceeds to find and develop the next largest set of oil fields. This large to small discovery and development process is predicated on the fact that developing new infrastructure in Alaska, particularly on the North Slope, is an expensive undertaking and that the largest fields enjoy economies of scale, which make them more profitable and less risky to develop than the smaller fields. Oil and gas exploration and production currently are not permitted in the Arctic National Wildlife Refuge. The projections for Alaska oil and gas production assume that this prohibition remains in effect throughout the projection period.Three uncertainties are associated with the Alaska oil projections. First, whether the heavy oil deposits located on the North Slope, which exceed 20 billion barrels of oil-in-place, will be producible in the foreseeable future at recovery rates exceeding a few percent. Second, the oil production potential of the North Slope shale formations is unknown at this time. Third, the North Slope offshore oil resource potential, especially in the Chukchi Sea, is untested. In June 2011, Alyeska Pipeline Service Company released a report regarding potential operational problems that might occur as Trans-Alaska Pipeline System (TAPS) throughput declines from the current production levels.[6] Although the onset of TAPS low flow problems could begin at around 550,000 barrels per day, absent any mitigation, the severity of the TAPS operational problems is expected to increase significantly as throughput declines. As the types and severity of problems multiplies, the investment required to mitigate those problems is expected to increase significantly. Because of the many and diverse operational problems expected to occur below 350,000 barrels per day of throughput, considerable investment might be required to keep the pipeline operational below this threshold. For the Annual Energy Outlook 2012 projections, an algorthim was installed into the Alaska Oil & Gas Supply Submodule that assumed that North Slope fields would be shut down, plugged, and abandoned when the following 2 conditions are simultaneously satisfied: 1) TAPS throughput would have to be at or below 350,000 barrels per day and 2) total North Slope oil production revenues would have to be at or below $5.0 billion per year. The Annual Energy Outlook 2012 Issues in Focus article, entitled: “The Potential Shutdown of Alaska North Slope Oil Production,” discusses these assumptions and their rationale.


Oil and Gas Supply ModuleLegislation and regulationsThe Outer Continental Shelf Deep Water Royalty Act (Public Law 104-58) gave the Secretary of the Interior the authority to suspend royalty requirements on new production from qualifying leases and required that royalty payments be waived automatically on new leases sold in the 5 years following its November 28, 1995 enactment. The volume of production on which no royalties were due for the 5 years was assumed to be 17.5 million barrels of oil equivalent (BOE) in water depths of 200 to 400 meters, 52.5 million BOE in water depths of 400 to 800 meters, and 87.5 million BOE in water depths greater than 800 meters. In any year during which the arithmetic average of the closing prices on the New York Mercantile Exchange for light sweet crude oil exceeded $28 per barrel or for natural gas exceeded $3.50 per million Btu, any production of crude oil or natural gas was subject to royalties at the lease-stipulated royalty rate. Although automatic relief expired on November 28, 2000, the act provided the Minerals Management Service (MMS) the authority to include royalty suspensions as a feature of leases sold in the future. In September 2000, the MMS issued a set of proposed rules and regulations that provide a framework for continuing deep water royalty relief on a lease-by-lease basis. In the model it is assumed that relief will be granted at roughly the same levels as provided during the first 5 years of the act. Section 345 of the Energy Policy Act of 2005 provides royalty relief for oil and gas production in water depths greater than 400 meters in the Gulf of Mexico from any oil or gas lease sale occurring within 5 years after enactment. The minimum volumes of production with suspended royalty payments are:(1) 5,000,000 barrels of oil equivalent (BOE) for each lease in water depths of 400 to 800 meters;(2) 9,000,000 BOE for each lease in water depths of 800 to 1,600 meters;(3)12,000,000 BOE for each lease in water depths of 1,600 to 2,000 meters; and

(4) 16,000,000 BOE for each lease in water depths greater than 2,000 meters.The water depth categories specified in Section 345 were adjusted to be consistent with the depth categories in the Offshore Oil and Gas Supply Submodule. The suspension volumes are 5,000,000 BOE for leases in water depths of 400 to 800 meters; 9,000,000 BOE for leases in water depths of 800 to 1,600 meters; 12,000,000 BOE for leases in water depths of 1,600 to 2,400 meters; and 16,000,000 for leases in water depths greater than 2,400 meters. Examination of the resources available at 2,000 to 2,400 meters showed that the differences between the depths used in the model and those specified in the bill would not materially affect the model result. The MMS published its final rule on the “Oil and Gas and Sulphur Operations in the Outer Continental Shelf Relief or Reduction in Royalty Rates Deep Gas Provisions” on January 26, 2004, effective March 1, 2004. The rule grants royalty relief for natural gas production from wells drilled to 15,000 feet or deeper on leases issued before January 1, 2001, in the shallow waters (less than 200 meters) of the Gulf of Mexico. Production of gas from the completed deep well must begin before 5 years after the effective date of the final rule. The minimum volume of production with suspended royalty payments is 15 billion cubic feet for wells drilled to at least 15,000 feet and 25 billion cubic feet for wells drilled to more than 18,000 feet. In addition, unsuccessful wells drilled to a depth of at least 18,000 feet would receive a royalty credit for 5 billion cubic feet of natural gas. The ruling also grants royalty suspension for volumes of not less than 35 billion cubic feet from ultra-deep wells on leases issued before January 1, 2001. Section 354 of the Energy Policy Act of 2005 established a competitive program to provide grants for cost-shared projects to enhance oil and natural gas recovery through CO2 injection, while at the same time sequestering CO2 produced from the combustion of fossil fuels in power plants and large industrial processes.From 1982 through 2008, Congress did not appropriate funds needed by the MMS to conduct leasing activities on portions of the Federal Outer Continental Shelf (OCS) and thus effectively prohibited leasing. Further, a separate Executive ban in effect since 1990 prohibited leasing through 2012 on the OCS, with the exception of the Western Gulf of Mexico and portions of the Central and Eastern Gulf of Mexico. When combined, these actions prohibited drilling in most offshore regions, including areas along the Atlantic and Pacific coasts, the eastern Gulf of Mexico, and portions of the central Gulf of Mexico. In 2006, the Gulf of Mexico Energy Security Act imposed yet a third ban on drilling through 2022 on tracts in the Eastern Gulf of Mexico that are within 125 miles of Florida, east of a dividing line known as the Military Mission Line, and in the Central Gulf of Mexico within 100 miles of Florida. On July 14, 2008, President Bush lifted the Executive ban and urged Congress to remove the Congressional ban. On September 30, 2008, Congress allowed the Congressional ban to expire. Although the ban through 2022 on areas in the Eastern and Central Gulf of Mexico remains in place, the lifting of the Executive and Congressional bans removed regulatory obstacles to development of the Atlantic and Pacific OCS.



Oil and gas supply alternative casesTight Oil and Shale Gas Resource casesEstimates of technically recoverable shale gas resources are highly uncertain and change over time as new information is gained through drilling, production, and technology experimentation. Over the last decade, as more shale formations have gone into production, the estimate of technically recoverable shale gas resources has skyrocketed. However, these increases in technically recoverable shale gas resources embody many assumptions that might not prove to be true over the long term and over the entire shale formation. For example, these shale gas resource estimates assume that gas production rates achieved in a limited portion of the formation are representative of the entire formation, even though neighboring shale gas well production rates can vary by as much as a factor of three. Moreover, the shale formation can vary significantly across the petroleum basin with respect to depth, thickness, porosity, carbon content, pore pressure, clay content, thermal maturity, and water content. Three cases were developed to examine the impact of the uncertainty inherent in these resource estimates by adjusting the estimated ultimate recovery (EUR) per well and the well spacing, both key components in the estimation of technically recoverable resources (see Issues in Focus article, U.S. Crude Oil and Natural Gas Resource Uncertainty). Low EUR case. In this case, the EUR per tight oil and shale gas well is assumed to be 50 percent lower than in the Reference case, increasing the per-unit cost of developing the resource. The total unproved technically recoverable tight oil resource is decreased to 17 billion barrels and the shale gas resource is decreased to 241 trillion cubic feet, compared to 33 billion barrels of tight oil and 482 trillion cubic feet of shale gas assumed in the Reference case.High EUR case. The EUR per tight oil and shale gas well is assumed to be 50 percent higher than in the Reference case, decreasing the per-unit cost of developing the resource. The total unproved technically recoverable tight oil resource is increased to 50 billion barrels and the shale gas resource is increased to 723 trillion cubic feet.High TRR case. The well spacing for all tight oil and shale gas plays is assumed to be 8 wells per square mile (i.e., each well has an average drainage area of 80 acres) and the EUR per tight oil and shale gas wells are assumed to be 50 percent higher than in the Reference case. Additionally, production in the short term from the eight tight oil plays was adjusted to reflect the latest available data. The total unproved technically recoverable tight oil resource is increased to 89 billion barrels and the shale gas resource is increased to 1,091 trillion cubic feet, more than twice the Reference case tight oil and shale gas resource assumptions.



Notes and sources[1] The current development of tight oil plays has shifted industry focus and investment away from the development of U.S. oil shale (kerogen) resources. Considerable technological development is required prior to the large-scale in-situ production of oil shale being economically feasible. Consequently, the Oil Shale Supply Submodule assumes that large-scale in-situ oil shale production is not commercially feasible prior to 2035.[2] Technically recoverable resources are resources in accumulations producible using current recovery technology but without reference to economic profitability.[3] Proved reserves are the estimated quantities that analysis of geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.[4] Unproved resources include resources that have been confirmed by exploratory drilling and undiscovered resources, which are located outside oil and gas fields in which the presence of resources has been confirmed by exploratory drilling; they include resources from undiscovered pools within confirmed fields when they occur as unrelated accumulations controlled by distinctly separate structural features or stratigraphic conditions.[5] Donald L. Gautier and others, U.S. Department of the Interior, U.S. Geological Survey, 1995 National Assessment of the United States Oil and Gas Resources, (Washington, D.C., 1995); U.S. Department of the Interior, Minerals Management Service, Report to Congress: Comprehensive Inventory of U.S. OCS Oil and Natural Gas Resources, (February 2006); and 2003 estimates of conventionally recoverable hydrocarbon resources of the Gulf of Mexico and Atlantic Outer Continental Shelf as of January 1, 2003. [6] Alyeska Pipeline Service Company, Low Flow Impact Study, Final Report, June 15, 2011, Anchorage, Alaska, at www.alyeska-pipe.com/Inthenews/LowFlow/LoFIS_Summary_Report_P6%2027_FullReport.pdf.

oil and gas supply module - u.s. energy information administration

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